1. Field of the Invention
The invention relates generally to drill bits used to drill wellbores through the earth. More particularly, the invention relates to polycrystalline diamond compact (“PDC”) drill bits having directional drilling characteristics.
2. Background Art
Drill bits in general are well known in the art. In recent years a majority of drag bits have been designed using hard PDC as cutting elements. The cutting elements are mounted on a rotary bit and oriented so that each PDC engages the rock face at a desired angle. The bit is attached to the lower end of a drill string and is typically rotated by rotating the drill string at the surface.
The cost of drilling a borehole is proportional to the length of time it takes to drill the borehole to the desired depth and location. The drilling time, in turn, is greatly affected by the number of times the drill bit must be changed in order to reach the targeted depth or formation.
In recent years, the PDC bit has become an industry standard for cutting formations of grossly varying hardnesses. The cutting elements used in such bits are formed of extremely hard materials and include a surface layer of polycrystalline diamond material. In the typical PDC bit, each cutter element or assembly comprises an elongate and generally cylindrical support member which is received and secured in a pocket formed in the surface of the bit body. A PDC cutter typically has a hard cutting layer of polycrystalline diamond exposed on one end of its support member, which is typically formed of tungsten carbide.
The configuration or layout of the PDC cutters on a bit face varies widely, depending on a number of factors. One of these is the formation itself, as different cutter layouts cut the various strata differently. In running a bit, the driller may also consider weight on bit (WOB), rotation speed (RPM), rate of penetration (ROP), and the weight and type of drilling fluid. Additionally, a desirable characteristic of the bit it that it be “stable” and resist vibration. A severe type or mode of destructive vibration is known as “whirl.” “Whirl” is a term used to describe the phenomenon wherein a drill bit rotates about an axis that gyrates offset from the geometric center of the drill bit. Whirling subjects the cutting elements on the bit to alternating increased loading and impact with the formation, which causes the premature wearing or destruction of the cutting elements and a loss of penetration rate. U.S. Pat. Nos. 5,109,935 and 5,010,789 disclose various techniques for reducing whirl by compensating for imbalance in a controlled manner. In general, optimization of placement and orientation of blades and cutters and overall design of the bit have been the objectives of extensive research efforts.
Directional and horizontal drilling have also been the subject of much research. Directional and horizontal drilling involves deviation of the borehole from vertical. Frequently, this drilling program results in boreholes whose remote ends are approximately horizontal. Advancements in measurement while drilling (MWD) technology have made it possible to track the position and orientation of the wellbore. Increasingly, accurate information about the location of the target formation is often available to drillers as a result of improved logging techniques and methods such as geosteering. These increases in available information have raised the expectations for drilling performance. For example, a driller today may target a relatively narrow, horizontal oil-bearing stratum, and may wish to maintain the borehole within the stratum once he has entered it. In more complex scenarios, highly specialized “design drilling” techniques are preferred, with highly tortuous well paths having multiple directional changes of two or more bends lying in different planes.
A common way to control the direction in which the bit is drilling is to steer using a turbine, downhole motor attached to a drill string and fixing a bent rod or “sub” behind the motor. As shown in FIG. 1, a simplified version of a downhole steering system according to the prior art comprises a rig 1, drill string 2, bent sub 4, motor 6 housed in bent sub 4, and drill bit 8. The motor 6 and bent housing 4 form part of the bottom hole assembly (BHA) and are attached to the lower end of the drill string 2 adjacent the bit 8. When not rotating, the bent housing causes the bit face to be canted with respect to the tool axis. The downhole motor is below the bend in the housing. The motor is capable of converting fluid pressure from fluid pumped down the drill string into rotational energy at the bit. This allows the bit to be rotated without rotating the drill string. When a downhole motor is used with a bent housing and the drill string is not rotated, the rotating action of the motor normally causes the bit to drill a hole that is deviated in the direction of the bend in the housing. When the drill string is rotated, the borehole normally maintains direction, regardless of whether a downhole motor is used, as the bent housing rotates along with the drill string and thus no longer orients the bit in a particular direction. Hence, a bent housing and downhole motor are effective for deviating a borehole.
When a well is substantially deviated by several degrees from vertical and has a substantial inclination, such as by more than 30 degrees, the factors influencing drilling and steering change. This change in factors reduces operational efficiency for a number of reasons.
First, operational parameters such as weight on bit (WOB) and RPM have a large influence on the bit's rate of penetration, as well as its ability to achieve and maintain the required well bore trajectory. As the well's inclination increases and approaches horizontal, it becomes much more difficult to apply weight on bit effectively, as the well bottom is no longer aligned with the force of gravity. Furthermore, the increasing bend in the drill string means that downward force applied to the string at the surface is less likely to be translated into WOB, and is more likely to cause the buckling or deforming of the drill string. Thus, attempting to steer with a downhole motor and a bent sub normally reduces the achievable rate of penetration (ROP) of the operation and makes tool control difficult.
Second, using the motor to change the azimuth or inclination of the well bore without rotating the drill string, a process commonly referred to as “sliding,” means that the drilling fluid in most of the length of the annulus is not subject to the rotational shear that it would experience if the drill string were rotating. Drilling fluids tend to be thixotropic, so the loss of this shear adversely affects the ability of the fluid to carry cuttings out of the hole. Thus, in deviated holes that are being drilled with the downhole motor alone, cuttings tend to settle on the bottom or low side of the hole. This increases borehole drag, making weight on bit transmission to the bit very difficult and causing problems with tool phase control and prediction. This difficulty makes the sliding operation very inefficient and time consuming.
Third, drilling with the downhole motor alone during sliding deprives the driller of the advantage of a significant source of rotational energy, namely the surface equipment that would otherwise rotate the drill string and reduce borehole drag and torque. The drill string, which is connected to the surface rotation equipment, is not rotated during drilling with a downhole motor. Additionally, drilling with the motor alone means that a large fraction of the fluid energy is consumed in the form of a pressure drop across the motor in order to provide the rotational energy that would otherwise be provided by equipment at the surface. Thus, when surface equipment is used to rotate the drill string and the bit, significantly more power is available downhole and drilling is faster. This power can be used to rotate the bit or to provide more hydraulic energy at the bit face, for better cleaning and faster drilling.
An alternate way to drill certain wellbores along a predetermined trajectory other than vertical for the purpose of penetrating selected earth formations at a subsurface position different from the surface position of the wellbore uses a drill bit designed according to a imbalance force method, such as the bits in U.S. Pat. Nos. 5,042,596 and 5,010,789. This design attempts to concentrate high imbalance loads toward a certain area of the drill bit. High imbalance loads are created using a cutting zone and bearing zone. The cutting zone includes a plurality of blades and cutting elements. The bearing zone is designed to slip along the borehole wall. A wear resistant surface is provided in the bearing zone area without cutting blades or cutters. The imbalance load compensated drill bits rely on static force calculations, and the static imbalance force often depends on the particular formation to be drilled.
Accordingly, there exists a need for drill bits which can maintain a constant uniform cutting path by applying a constant offset radial force.